Method of drilling and running casing in large diameter wellbore

ABSTRACT

A well is drilled and casing installed utilizing a casing drilling technique. A bottom hole assembly having a drill bit and a fluid diverter is secured to a string of drill pipe and installed within a casing string. Drilling fluid is pumped down the drill pipe string to cause the drill bit to rotate and drill the well while the fluid diverter is in a drilling mode position, At the total depth for the casing string, the operator moves the fluid diverter to a cementing position and pumps cement down the drill pipe and up the casing string annulus. After cementing, the operator moves the fluid diverter to a packer set position and again pumps drilling fluid down the drill string to set the packer.

FIELD OF THE INVENTION

This invention relates in general to well drilling operations, and inparticular to a method of drilling and running casing simultaneously inlarge diameter wellbores.

BACKGROUND OF THE INVENTION

Normally wellbores for well and gas wells have a larger diameter orsurface easing portion at the upper end that will be cased by a firststring of casing. One or more strings of casing are subsequentlyinstalled with each string of casing being smaller in diameter. Thefirst string of casing in a subsea well may be as large as 36″ indiameter, Typically, the operator jets or washes the first casing stringinto the seabed to a depth of about 400 feet. The operator accomplishesthis installation by pumping fluid down the casing string to wash outthe seabed as the casing is lowered. The surrounding formation settlesin and around the casing string, holding it in place. The operator mayalso cement the first string of casing.

A subsea outer wellhead housing may be located at the upper end of thefirst string of casing on the sea floor. In other techniques, the firststring of casing extends upward to a fixed platform above the sea level,and a wellhead housing is attached to the casing at the platform. Theoperator drills through the first string of casing to a second depth,then installs a second string of casing. The operator may repeat thisprocess, installing a third or more strings of casing.

In some cases, having a longer first string of casing is desirable, suchas one having a depth of about 1500 feet. A deeper first string ofcasing is helpful particularly for deep wells. However, increasing thedepth of the first string of casing in subsea wells is not easy toachieve by jetting or washing down a large diameter string of pipe.

Techniques other than jetting or washing down surface casing are known.For example, operators normally install the first string of casing inland-based wells by first drilling the wellbore with a drill bit, thenlowering the first string of casing string into the well and cementingit in place. The first string of casing for a land-based well isnormally not as large as the first string of casing of a subsea well.

Although not typically done offshore, casing, include a first string ofcasing, may also be installed simultaneously as the well is beingdrilled. In this technique, the operator installs a bottom hole assemblyat the lower end of a string of casing being made up. The bottom holeassembly includes a drill bit and a locking mechanism that locks thebottom hole assembly to the casing string for rotation in unison witheach other. The operator grips the upper end of the casing string with acasing gripper. The top drive supports and rotates the casing gripperand the casing string, causing the drill bit to rotate to drill thewell. When reaching a desired depth, the operator optionally mayretrieve the bottom hole assembly while the casing remains in the well.The operator then cements the easing in place.

Casing while drilling becomes difficult in the case of very largediameter casing. One reason is that large diameter casing may not havethe strength to transmit the necessary torque throughout its length. Thefriction between the large diameter casing string and the boreholesidewall can be high.

Mud motors are sometimes used in drill strings for causing rotation ofthe drill bit relative to the drill pipe. A mud motor operates inresponse to drilling fluid pumped down the drill pipe string. Mud motorsare particularly useful for drilling horizontal or directional wells.Mud motors may also be installed in a bottom hole assembly of a casingdrilling assembly. The reactive torque caused by the mud motor can betransmitted back to the casing string, which may be maintained in anon-rotating position. Rotating the casing string while casing drilling,however, is desirable to smear and condition the mudcake on the boreholewalls. Thus, the operator typically will rotate the casing string at thesame time the mud motor is operating. The casing will rotate in the samedirection but at a slower speed than the mud motor, if so, The operatorcauses the casing string to rotate by rotating the casing gripper withthe top drive.

During casing while drilling of land-based wells, the upper end of thestring of casing will be located at the drilling rig and gripped androtated by a casing gripper. Extending the upper end of the string ofcasing to the drilling rig during a casing drilling operation may not befeasible for an offshore well located in deep water. If the upper end ofthe casing string, once installed, is to be supported by a subseawellhead assembly, the operator would not want the upper end of thecasing string to extend any higher than the subsea wellhead assembly.Otherwise, the operator would have to unscrew each joint of casingextending above the subsea wellhead assembly, and the sea floor may bethousands of feet deep.

Liner drilling is another technique involving deploying a string ofcasing while drilling. A liner string is made up of joints of pipe thatare the same as casing and which are cemented in the well. A differenceis that the liner string extends only a short distance above the lowerend of the previously installed casing string. Casing strings, cm theother hand, extend to the top of the well. In liner drilling, a selectedlength of casing is made up with a bottom hole assembly having a drillbit. The liner is deployed on a string of drill pipe, and rotation isimparted to the liner string by the string of drill pipe. The drill pipemay connect to the upper end of the liner string and transmit torquethrough the liner string to the bottom hole assembly. Alternately, thedrill pipe may extend concentrically within the liner string to thebottom hole assembly. The liner string is mounted to the drill pipe forrotation with the drill pipe, thus some of the torque would pass throughthe liner string and some through the drill pipe to the bottom holeassembly.

SUMMARY OF THE INVENTION

In one embodiment of the invention, the operator makes up a casingstring and secures a drill pipe string to a bottom hole assembly. Thebottom hole assembly has an earth boring bit and a fluid diverter. Thefluid diverter has a drilling position and a cementing position. Whilein the drilling position, the operator rotates the drill bit to drillthe well, and pumps drilling fluid down the drill pipe string while thefluid diverter is in a drilling mode position. In the drilling position,the drilling fluid flows through the drill pipe to the bottom holeassembly and out the drill bit.

When reaching a total depth of the casing string, the operator moves thefluid diverter to the cementing position and pumps cement down the drillpipe. The cement flows out the drill pipe string above the drill bit andup the casing string annulus on the exterior of the casing string. Theoperator then retrieves the bottom hole assembly from the casing string.

In one technique, the operator moves the fluid diverter to the cementingposition by conveying a sealing member into the drill pipe stringpassage, which lands in the fluid diverter to block flow through thedrill pipe to the bottom hole assembly and direct the cement along acement path to the casing string annulus.

In another embodiment, the operator installs a packer in the casingstring while the casing string is being made up. After dispensing thecement and before retrieving the bottom hole assembly, the operatormoves the flow diverter to a packer set position and pumps fluid downthe drill string to set the packer, The packer extends outward to sealthe casing string annulus, preventing cement in the casing stringannulus from flowing downward.

In one technique, the operator moves the fluid diverter to the packerset position by conveying another sealing member down the drill pipestring passage, which lands in the fluid diverter to block flow alongthe cement path and direct downward flow to the packer to set thepacker.

In another embodiment of the invention, the fluid diverter has a barrierthat seals against the inner diameter of the casing string to blockupward return flow within the interior of the casing string. In thisembodiment, the fluid diverter includes a bypass port and a bypass valvethat will selectively allow drilling fluid to be returned up theinterior of the casing. Moving the fluid diverter from the drillingposition to the cementing position preferably automatically closes thebypass port.

In another embodiment of the invention, the bottom hole assembly has amud motor that is driven by drilling fluid pressure. The operatorrotates the drill bit with the mud motor. The operator transmitsreacting torque caused by the mud motor to the casing string. The upperend of the casing string is preferably not attached to the drill pipefor rotation therewith, thus the drilling torque is not transferred tothe casing string. The operator causes the reacting torque to rotate thecasing string in reverse, but controls the rate of rotation in thereverse direction by applying a braking force to the drill pipe string.The braking force may be applied by a top drive of the drilling rig.This technique of causing the casing string to rotate in reverse to thedrill bit may be employed for liner drilling as well as casing drilling,both offshore and on land.

Causing reverse rotation of the casing string by utilizing the torque ofa mud motor can also be employed with casing drilling operations whetheror not a fluid diverter is employed. In this instance, the bottom holeassembly may be land and lock in the casing string without any drillpipe attached to it. The operator connects the upper end of the casingstring to a casing gripper support by a top drive. The reverse torqueapplied to the casing string extends up the casing string to the casinggripper and top drive. The top drive applies a braking action to thereverse rotation of the casing string.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 is a schematic view of a casing string having a fluid diverterand being operated in a drilling mode in accordance with this invention.

FIG. 2 is a schematic view of the casing string of FIG. 1, showing thefluid diverter in a cementing position.

FIG. 3 is a schematic view of the casing string of FIG. 1, showing thecement dispensed and a packer set by the fluid diverter, which is in apacker set position.

FIG. 4 is a sectional view of the fluid diverter and packer of thecasing string of FIG. 1.

FIG. 5 is a perspective view of the fluid diverter of FIG. 4, showndetached from the packer.

FIG. 6 is an enlarged sectional view of an upper portion of the housingof the fluid diverter of FIG. 4, illustrating a shear pin that holds thetorque keys of the fluid diverter in an engaged position.

FIG. 7 is a schematic sectional view of the fluid diverter of FIG. 4,and shown in the drilling position.

FIG. 8 is a top view of the fluid diverter of FIG. 7.

FIG. 9 is a bottom view of the fluid diverter of FIG. 7.

FIG. 10 is another sectional view of the fluid diverter of FIG. 7,showing the fluid diverter in a cementing mode.

FIG. 11 is a sectional view of the bypass valve of the fluid diverter ofFIG. 10, shown removed from the fluid diverter and illustrated in adrilling mode position.

FIG. 12 is a sectional view of the bypass valve of FIG. 11, and showingthe bypass valve in a cementing mode.

FIG. 13 is a sectional view of the fluid diverter of FIG. 10 and showingthe fluid diverter in a packer set position.

FIG. 14 is a sectional view of the fluid diverter of FIG. 13, andshowing the fluid diverter in a retrieval position.

FIG. 15 is a schematic view of an alternate embodiment of a casingstring, showing a casing gripper and a bottom hole assembly beingoperated in accordance with an alternate embodiment method.

DETAILED DESCRIPTION OF THE INVENTION

Referring to FIG. 1, a casing string 11 is illustrated forming an openhole 13 of a well below seafloor 15. Casing string 11 is made up ofsections of casing, each approximately 30 to 40 feet in length, securedtogether by threads. Although the word “casing” is utilized, casingstring 11 may also be considered a liner string. A liner string is madeup of well pipe that is the same as casing and is cemented in place, butdiffers from casing in that the liner upper end will be installed justabove the lower end of a previously installed string of casing. The term“casing string” typically refers to well pipe that is cemented in placeand extends all the way to a wellhead. The term “casing string” as usedherein is meant to include also liner strings. Also, at least some ofthe techniques described herein are applicable to wells drilled on landlocations.

In FIG. 1, a wellhead component such as an outer wellhead housing 17, isillustrated at the upper end of casing string 11. After casing string 11is cemented in place, as shown in FIG. 3, wellhead housing 17 will be atseafloor 15. However, this invention is also applicable to casingstrings that extend upward to a platform above sea level, where thewellhead would be located.

Casing string 11 may include a packer 19, which is a conventionalelastomeric sleeve, such as an external casing packer, either inflatableor mechanical, that will expand to a larger diameter when set, asillustrated in FIG. 3. When set, packer 19 seals against the boreholewall of borehole 13. Preferably, packer 19 is of a type that remains setonce the setting mechanism is energized, even after the settingmechanism has been removed. For example, the setting mechanism may beactuated by fluid pressure, and a device such as a check valve isemployed to prevent packer 19 from releasing from the set position afterthe fluid pressure is removed.

A profile sub 21 is connected in casing string 11 below packer 19 inthis embodiment. Profile sub 21 is a tubular member that has grooves ora profile formed in its interior for purposes to be subsequentlyexplained. Profile sub 21 may be located at the lower end of casingstring 11, or some of casing string 11 may extend below profile sub 21.

A drill pipe string 23 is shown suspended from a top drive 24 of thedrilling rig and inserted concentrically into casing string 11. Topdrive 24 is a conventional device employed by many drilling rigs to liftand rotate lengths of drill pipe. Top drive 24 runs up and down aderrick (not shown). An axial locking device 25 is connected into drillpipe string 23 for engaging an upper end of casing string 11 to supportthe weight of casing string 11. Axial locking device 25 may be a varietyof types, including support members or dogs that are actuated radiallyoutward into recesses at the upper end of casing string 11, such aswithin outer wellhead housing 17. In the preferred embodiment, axiallocking device 25 does not transmit rotation to casing string 11 norreceive any torque from it.

A telescoping joint 27 may be located within drill pipe string 23 belowlifting device 25. Telescoping joint 27 is a sub that will telescopebetween various lengths. In this example, it does not transmit anytorque in drill pipe string 23 from below to above. However, in analternate embodiment, it could be configured for transmitting torquethrough drill pipe string 23.

A bottom hole assembly (BHA) 29 is secured to the lower end of drillpipe string 23 with a stab-in connector 30 located on a central conduitextending upward from BHA 29, BHA 29 includes a fluid diverter 31 thatwill be subsequently described and which is located below the stab-inconnector 30. A mud motor 33 is mounted below fluid diverter 31 withinBHA 29. Mud motor 33 is a conventional drilling fluid motor that rotatesin response to drilling fluid pumped down drill pipe string 23. Anunderreamer 35 attaches the lower end of mud motor 33. A drill bit 37attaches to the lower end of underreamer 35. Underreamer 35 and drillbit 37 are conventional devices for disintegrating the earth formation.Underreamer 35 has arms that will collapse so that it can be retrievedthrough casing string 11, in the extended position shown in FIG. 1,underreamer 35 has an outer diameter greater than the outer diameter ofcasing string 11.

Fluid diverter 31 has an outer diameter that seals to the inner diameterof casing string 23. Fluid diverter 31 has a drilling mode that allowsdrilling fluid to flow upwardly through fluid diverter 31 as indicatedby arrows 39 in FIG. 1. Fluid diverter 31 also has a cementing mode, asillustrated in FIG. 2. In the cementing mode, a closure member 41 withinthe passage of drill pipe string 23, blocks any fluid flow to drill bit37. As indicated by arrow 43, cement being pumped down drill pipe string23 will flow down into an annulus in casing string 11 surrounding drillpipe string 23 below fluid diverter 31. Cement flow into the drillpipe-casing annulus is also blocked by fluid diverter 31 after it isactivated. Fluid diverter 31 also has a packer set mode that isillustrated in FIG. 3. In the packer set mode, fluid pumped down drillpipe string 23 is discharged out to packer 19 to cause it to inflate orset as indicated by arrows 45.

Briefly explaining the operation, prior to running in, BHA 29 isassembled along with fluid diverter 31, packer 19 and stab-in connector30 and hung off in the rotary table of the drilling rig. Then casingstring 11 is assembled on bottom hole assembly 29 and run through therotary and hung off. Next, drill pipe string 23 together withtelescoping joint 27 is run in and stabbed into stab-in connector 30 ofbottom hole assembly 29. Telescoping joint 27 allows the required spaceout by first tagging the mating connector on the lower end of drill pipestring 23 with stab-in connector 30 without making the connection. Then,the properly spaced out drill pipe 23 is connected to the casing runningtool 25, which in turn is connected to casing string 11. The assembly ofcasing 11 can now be run in for BHA 29 to contact the sea floor or thebottom of a previously formed portion of the wellbore.

The operator pumps drilling mud down drill pipe string 23, whichdischarges out ports in drill bit 37. The drilling fluid also actuatesdrill motor 33, causing it to rotate underreamer 35 and drill bit 37. Inthis example, the operator does not rotate drill pipe string 23 with topdrive 24. Instead, the operator sizes mud motor 33 so that it has enoughtorque to cause casing string 11 to spin in reverse to the direction ofrotation of drill bit 37. The reaction of the torque created by mudmotor 33 transmits through fluid diverter 31 to profile sub 21 of casingstring 11 and to drill pipe 23 connected to diverter 31. If casingstring 11 were allowed to freely spin, there may be inadequate torque tocause drill bit 37 to rotate and disintegrate the earth formation. Theoperator thus applies a brake with top drive 24 to cause drill pipe 23and casing string 11 to rotate more slowly in reverse than the forwardrotational speed of drill bit 37. The braking action leaves adequatetorque to be applied to drill bit 37 so that it will disintegrate theearth formation and form borehole 13. The rotation of casing string 11and drill pipe string 23 in reverse is applied to the bottom of casingstring 11 and drill pipe string 23, thus it will not cause the pipeconnections in casing string 11 or drill pipe string 23 to unscrew. Thisapplication of torque results in right hand torque to the pipeconnections above the point of application of torque. This reverserotation of casing string 11 has a beneficial effect of causing casingstring 11 to smear and form a mud cake on the sidewall of borehole 13.As the casing string 11 gets deeper within borehole 13, friction willrise, allowing the braking action to be reduced to control therotational speed in reverse as well as assure adequate torque forrotating drill bit 37 in the forward direction.

As drill bit 37 drills, the drilling fluid discharged has two returnpaths in this embodiment. One return path is the casing annulus betweenthe sidewall of borehole 13 and the exterior of casing string 11. Theother return path is up the interior of casing string 11 through fluiddiverter 31 as indicated by arrows 39.

When reaching the total depth as illustrated in FIG. 2, the operatorshifts fluid diverter 31 to the cementing mode. In the cementing mode,closure member 41 blocks downward flow from drill pipe string 23 todrill bit 37. Also, in this mode, fluid diverter 31 diverts the downwardflow in drill pipe string 23 to the drill pipe annulus surrounding drillpipe string 23 below fluid diverter 31, as indicated by arrow 43.Additionally, diverter 31 shuts off the flow path to the annulus betweendrill pipe string 23 and casing 11. The operator then pumps cement 44down drill pipe string 23 to the drill pipe annulus; the cement turns atthe bottom of borehole 13 and flows back up the casing annulus, asillustrated in FIG. 3.

When the desired amount of cement 44 has been deployed, in thisembodiment, the operator shifts fluid diverter 31 to the packer setposition. Closure 41 still prevents downward flow in drill pipe string23 below fluid diverter 31 to drill bit 37. The operator pumps drillingfluid or water down drill pipe string 23, as indicated by arrows 45. Thedrilling fluid or water flows out to the inlet ports of packer 19,causing it to set. When set, packer 19 prevents cement 44 from flowingback downward in the casing string annulus before cement 44 cures.

Afterward, the operator releases fluid diverter 31 from profile sub 21in casing string 11 and retrieves fluid diverter 31, BHA 29 and drillpipe string 23 to the surface. After releasing fluid diverter 31 fromprofile sub 21, the operator may pump a fluid such as water down drillpipe string 23, which will discharge out the same ports as indicated byarrows 45 but the flow will then be used for cleaning underreamer 35 anddrill bit 37.

A preferred embodiment of fluid diverter 31 is illustrated in FIGS.4-14. Referring to FIG. 4, packer 19 comprises an elastomeric sleevemounted over an inner tubular member 46. In one example, ports areprovided at the base of packer 19 to allow fluid entry between tubularmember 46 and the elastomeric sleeve of packer 19 to cause the sleeve toinflate. Alternately, packer 19 could be a type that has an annularpiston on one end that is pushed axially toward the other end inresponse to fluid pressure to deform the elastomer sleeve radiallyoutward. In each case, packer 19 has a mechanism to hold it in the setposition once set.

Fluid diverter 31 has a mandrel 47 with an upper threaded end forconnection to a lower end of the drill pipe string 23. The lower end ofmandrel 47 also is threaded in this example, for connecting to theremaining portions of BHA 29 (FIG. 1). Mandrel 47 is tubular, having aninterior mandrel passage 49 extending from its upper to its lower end.

A tubular housing 51 has a central bore that receives mandrel 47.Housing 51 is also carried on mandrel 47 for movement between a lowerposition (FIG. 14) and an upper position (FIGS. 5-7, 10 and 13). Asillustrated in FIG. 6, a shear pin 53 is mounted to a component ofhousing 51 at its upper end. Shear pin 53 is biased inward by a spring55 in this example. When moved to the upper position, which is a lockedmode, shear pin 53 will snap into engagement with an annular recess 57extending around mandrel 47. The retrieval position is shown in FIG. 14.

Referring to FIG. 5, mandrel 47 has an exterior cam surface 61. Whenmandrel 47 and housing 51 are in the locked position shown in FIG. 5,cam surface 61 will be in engagement with the inner ends of a pluralityof rods 63. Rods 63 extend radially outward and have outer endsconnected to torque keys 65. When pushed outward by rods 63, each torquekey 65 engages an axial spline 69 (FIG. 4) in profile sub 21 to transmittorque between profile sub 21 and fluid diverter 31, Additionally,torque keys 65 axially lock diverter 31 to profile sub 21. When runningfluid diverter 31 into casing string 11 (FIG. 1), mandrel cam surface 61will be spaced upward above rods 63, and torque keys 65 will berecessed.

In this example, torque keys 65 are housed within an annular recess onthe outer diameter of a lower ring 67. Lower ring 67 extendsconcentrically around outer housing 51. Lower ring 67 is rigidly securedto outer housing 51 by a plurality of axially extending webs 68. Webs 68are thin vertical plates that have their inner edges joined to housing51 and the outer edges joined to the inner diameter of lower ring 67.FIG. 9 illustrates the lower edges of webs 68.

Referring to FIG. 7, a plurality of cement ports 71 extend radiallyoutward through mandrel 47. The outer ends of cement ports 71 join anannular recess or gallery on the outer diameter of mandrel 47. Acementing valve sleeve 73 is carried within axial passage 49 of mandrel47 between an upper closed position, which is shown in FIG. 7, and alower open position which is shown in FIG. 10. In the closed position,cementing valve sleeve 73 blocks flow from passage 49 through cementports 71. Cementing valve sleeve 73 has an interior passage with a seat74.

A cement flow tube 75 has a radial portion that extends radially outwardthrough a hole in housing 51 and is in registry with the annular gallerysurrounding cement ports 71. Cement flow tube 75 has a cement outlet 77located within a cylinder 79 that extends downward from an outer end ofcement flow tube 75. An annular piston 81 in cylinder 79 moves from anupper position shown in FIGS. 7 and 11 to a lower position shown inFIGS. 10 and 12. Piston 81 has a seal on its outer diameter that sealsto the inner diameter of cylinder 79 above cement outlet 77. Piston 81also has an inner bore that slidingly and sealingly receives a shaft 83.

Shaft 83 extends downward below cylinder 79 and sealingly upward througha cap 84 attached to an upper side of cement flow tube 75. Shaft 83 isurged upward by a coil spring 85 and has a bypass valve member 87 on itsupper end. Spring 85 is compressed between cap 84 of cement flow tube 75and valve member 87, biasing shaft 83 in an upward direction. Valvemember 87 and shaft 83 will move upward when moving from the drillingfluid mode position in FIG. 11 to the cementing position in FIG. 12. Ashear pin 88 initially secures piston 81 to shaft 83, preventing shaft83 from moving upward from the position shown in FIG. 11. Fluid pressureapplied to the interior of cement flow tube 75 will act against piston81, and if at a sufficient level, the fluid pressure will shear pin 88.This allows piston 81 to drop by gravity and fluid pressure downward tothe position of FIG. 11 It also allows shaft 83 and bypass valve member87 to move upward to the position of FIG. 12.

When bypass valve member 87 moves upward, it will sealingly engage abypass port 89 extending through a closure plate 91. Closure plate 91 ismounted in a plane perpendicular to the axis of mandrel 47. Closureplate 91 has an inner diameter sealingly secured to the outer diameterof housing 51. It has an outer diameter that joins an upper ring 93.Upper ring 93 has approximately the same diameter as lower ring 67 andis mounted above it. Upper ring 93 has one or more seals 95 on its outerdiameter for sealingly engaging the inner diameter of casing string 11(FIG. 1). When valve member 87 is in the closed position shown in FIG.10, no upward flowing fluid within casing string 11 will be able to passabove fluid diverter 31 because of upper ring 93, seals 95 and closureplate 91. While valve member 87 is in the open position shown in FIG. 7,fluid from below fluid diverter 31 is free to flow upward through lowerring 67 around cement flow tube 75 and upward through bypass port 89.FIG. 5 illustrates closure plate 91 and upper ring 93 from a differentperspective.

Referring again to FIG. 7, a packer set or inflate tube 97 is shownextending from the inner diameter of housing 51 radially outward throughthe outer diameter of upper ring 93. Preferably there are more than onepacker inflate tube 97, and FIG. 8 shows three. The outlets of packerinflate tubes 97 are located within a recessed portion of the outerdiameter of upper ring 93. Recessed portion 98 has an outer diameterthat is less than the outer diameter defined by seals 95. One of theseals 95 is located below the outlet of packer inflate tubes 97 and theother above. Consequently, an annular chamber is achieved between upperring 93 and casing string 11 to allow fluid pressure to be communicatedto an interior port (not shown) of packer 19 (FIG. 4).

Referring still to FIG. 7, mandrel 47 has an annular recess 99 on itsexterior that is in fluid communication with the inlets of packerinflate tubes 97. Annular recess 99 has a length selected such that itwill be in fluid communication with packer inflate tubes 97 whilemandrel 47 is in the lower position relative to housing 51 as shown inFIG. 7 and also while in the upper position as shown in FIG. 14.

Annular recess 99 is in fluid communication with a plurality of packerset or inflate ports 101. Packer inflate ports 101 extend radiallythrough the sidewall of mandrel 47. A packer inflate valve sleeve 103 issealingly carried within mandrel 47. In the position shown in FIG. 7,packer inflate sleeve 103 blocks any flow from mandrel passage 49 outpacker inflate ports 101. When moved to the lower position shown in FIG.14, downward flowing fluid from mandrel passage 49 passes through packerinflate ports 101 and packer inflate tubes 97. Packer inflate sleeve 103has an axial passage with a seat 104 that is larger in diameter thanseat 74 in cementing valve sleeve 73. Packer sleeve 103 is independentlymovable relative to cementing valve sleeve 73. Both valve sleeves 73,104 may be releasably held by shear pins in their initial upperpositions shown in FIG. 7.

During operation, the operator then pumps drilling fluid down drill pipestring 23, which flows down mandrel passage 49, through valve sleeves 73and 103 and out nozzles in drill bit 37 (FIG. 1). The drilling fluidenergizes mud motor 33, which rotates drill bit 37. Some of the drillingfluid being discharged flows up the casing string annulus on theexterior of casing string 11. Some of the drilling fluid flows up theinterior of casing string 11. Referring to FIG. 7, the returningdrilling fluid is able to flow up the interior of casing string 11because it flows through open bypass port 89.

When the drilling is completed, the operator conveys a first sealingmember 105, such as a ball or dart into drill pipe string 23. Preferablythe operator pumps drilling fluid, causing first sealing member 105 toland in seat 74 of cement valve sleeve 73, as shown in FIG. 10. Firstsealing member 105 has a diameter that allows it to pass through seat104 in packer inflate valve sleeve 103. Increasing the pressure of thedrilling fluid shears a shear pin that holds cementing valve sleeve 73in the upper position, then causes cementing valve 73 to move to thelower position. When first sealing member 105 lands on seat 74, it willblock any downward flow from drill pipe string 23 past it. The downwardmovement of cementing valve sleeve 73 exposes cement ports 71 anddiverts fluid flowing down mandrel passage 49 out through cement flowtube 75 to act against piston 81. The fluid pressure shears pin 88,which causes spring 85 to move valve member 87 upward to close port 89.Shearing pin 88 also causes piston 81 to drop down to the lowerposition, exposing cement outlet 77. The drilling fluid will flow downthe interior of casing string 23 around BHA 29, as shown in FIG. 2. Thereturning drilling fluid now can return only up the exterior annulus ofcasing string 21 since bypass port 89 is closed, Packer inflate valvesleeve 103 remains in its upper position.

Once circulation is established in this manner, the operator will thenpump a quantity of cement 44 (FIG. 3) down drill pipe string 23.Referring again to FIG. 10, the cement flows out cementing outlet 77 anddown the interior of casing string 11, Cement 44 flows out the lower endof casing string 11 and back out the casing annulus on the exterior ofcasing string 11. The closed bypass valve member 87 prevents any cementfrom flowing upward within casing string 11 above fluid diverter 31.

When the desired quantity of cement has been dispensed, the operatorpumps down a second sealing member 107, as illustrated in FIG. 14.Sealing member 107 has a larger outer diameter than sealing member 105(FIG. 10) thus lands in seat 104 and seals the bore of packer inflatevalve sleeve 103. The fluid pressure shears the shear pin holding valvesleeve 103 in the upper position, causing valve sleeve 103 to movedownward and expose packer inflate ports 101. The operator pumpsdrilling fluid of cement down drill pipe string 23, which flows downmandrel passage 49 through packer inflate ports 101 and packer inflatetubes 97. This fluid is employed to inflate or set packer 19 (FIG. 3).Once set, packer 19 stays set, allowing the operator to stop pumpingfluid and begin retrieval.

To retrieve, the operator disengages axial locking device 25 (FIG. 1)from outer wellhead housing 17. That step may include partial rotation,downward movement or upward movement or other manipulation of drill pipestring 23. When the operator pulls upward, as shown in FIG. 14, thetension will cause shear pin 53 to shear, allowing mandrel 47 to againmove to the upper position relative to housing 51. Torque keys 65 arenow free to retract, After releasing and free of the engagement withprofile sub 21, the operator may pump drilling fluid down drill pipestring 23 and through mandrel passage 49. Packer inflate tubes 97 arestill in fluid communication with packer inflate ports 101 and mandrelpassage 49. Consequently, the cleaning fluid is free to discharge andflow within the interior of casing string 11 to clean drill bit 37 andunder reamer 35 (FIG. 1).

FIG. 15 illustrates an alternate embodiment of a feature that allows thecasing string 110 to rotate in reverse to the direction of rotation ofdrill bit 37 when rotated by mud motor 33. Common components are shownby the same numerals. In this embodiment, bottom hole assembly 109 isnot located at the lower end of a string of drill pipe during thedrilling operation. However, it could be run on the drill pipe and thedrill pipe retrieved, if desired. Bottom hole assembly 109 has a lockingcollar 111 that locks bottom hole assembly 109 to a profile sub 115.Locking collar 111 has torque keys 113 that engage splines in the samemanner as torque keys 65 (FIG. 5) of the first embodiment. Lockingcollar 111 preferably also has axial locking members 117. Axial lockingmembers 117 move radially inward and outward to lock bottom holeassembly 109 to profile sub 115. One or more seals 119 on bottom holeassembly 109 engages the inner diameter of casing string 110. A casinggripper 121 is mounted to top drive 24. Casing gripper 121 has grippingmembers 123 that will move radially outward to grip the interior of theupper end of casing string 110. Alternately, gripping members 123 couldbe employed to move radially inward to grip the exterior of casingstring 110.

During the operation of FIG. 15, drilling fluid is pumped through topdrive 24, casing gripper 121 and down the interior of easing string 110.The drilling fluid flows down bottom hole assembly 109 to cause mudmotor 33 to rotate drill bit 37 and underreamer 35 relative to casingstring 110. The reactive torque of mud motor 33 is transferred fromlocking collar 111 to profile sub 115. The reactive torque will tend tocause casing string 110 to rotate in reverse. The operator applies abraking force with top drive 24 to casing gripper 121 to resist rotationto some extent. Some of the torque is allowed to rotate casing string110 in reverse to the direction of rotation of drill bit 37. As casingstring 110 moves deeper into wellbore 13, the frictional effect ofcasing string 110 against the sidewall of borehole 13 increases. Thisfrictional effect allows the operator to reduce the braking actioncaused by top drive 24 but still allow some reverse rotation. Thetechnique of FIG. 15 could be applied whether or not a fluid divertersuch as fluid diverter 31 is utilized. This technique is applicable bothto land and offshore drilling.

While the invention has been shown in only a few of its forms, it shouldbe apparent to those skilled in the art that it is not so limited but issusceptible to various changes without departing from the scope of theinvention.

1-19. (canceled)
 20. A fluid diverter, comprising: a tubular mandrelwith a threaded upper end for connection to a drill pipe string and alower end for connection to a drill bit assembly, the mandrel having amandrel passage for receiving fluid pumped down a drill pipe stringpassage; a housing surrounding and carried by the mandrel; a diverterport in the housing having an inlet in fluid communication with themandrel passage and having an outlet exterior of the housing; and aremotely actuated cementing valve that closes the diverter port whilethe fluid diverter is in a drilling mode and opens the diverter portwhile the fluid diverter valve is in a cementing mode.
 21. The fluiddiverter according to claim 20, further comprising: a seal assemblymounted to the housing and extending radially therefrom for sealingengagement with an inner diameter of the casing string; a bypass port inthe seal assembly and extending from a lower to an upper side of theseal assembly; and a remotely actuated bypass valve that opens thebypass port while the fluid diverter is in the drilling mode and closesthe bypass port while the fluid diverter is in the cementing mode. 22.The fluid diverter according to claim 20, further comprising: a packeradapted to be connected into the casing string; a packer set portextending through the mandrel and the housing into fluid communicationwith the packer; and a remotely actuated packer set valve that is closesthe packer set port while the fluid diverter is in the drilling andcementing modes and opens the packer set port while in the packer setmode.